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Tidal data recorded in the German Bight over the last 200yrshow that MHW (mean high water) has risen by about 20 to 30cm per century. Corresponding data on maximum flood levels over the last 400 yr show a similar increase of approximately 25 cm per century. At Cuxhaven, the graph of maximum annual water levels drawn from 150 yr of continuous recordings reveals a long term oscillation superimposed on the progressive linear increase in water levels. This oscillation has a period of roughly 80 yr and extrapolation suggests the next peak should occur around 1985.These rates of increase in sea level over recent centuries are compared against the perspective of much longer term trends.Preface (D. Prandle, Institute of Oceanographic Sciences, Bidston Observatory, Merseyside)

In certain North Sea fields, barium levels of 250 ppm in formation water can lead to downhole sulphate scale deposition. Conventional treatment involved a squeeze inhibitor deployed through an aqueous phase. However, a squeeze treatment of low water-cut wells in water-sensitive formations and/or those with poor well lifting ability may result in negative wettability effects, formation damage by water blocking, and temporary process upsets. This paper describes the development of a new chemistry designed into an optimized squeeze package that has successfully mitigated formation damage and provided extended squeeze life time in the field. Significant permeability reductions were observed for both the Clashach formation and the reservoir during core flood tests when this new chemistry was applied in an aqueous package. The authors will discuss and identify the mechanisms of formation damage and its mitigation. Reformulation of the squeeze package focuses on the most cost-effective solution. A final reservoir core flood was conducted using a partially non-aqueous package consisting of a mutual solvent pre-flush stage prior to the injection of the main pill and aqueous overflush. The outcome of this treatment was very promising, as no permeability reduction was observed following the treatment and modeling of the squeeze life time yielded impressive predictions. A squeeze treatment using this optimized package was deployed successfully in the field, where no process upset was observed and no emulsion breaker was required during start up. Increased oil production was noted after the treatment and extended squeeze life time (>180 days) was obtained with in excess of 650,000 m3 of water protected. The inhibitor return was still over the MIC (Minimum Inhibitor Concentration) when the well was re-squeezed using the same package. The authors discuss performance of the field trial and compare it with previous treatments. Introduction Appropriate squeeze chemical inhibitors typically are required to manage the potential of a downhole scale problem, in particular the risk and uncertainty of barium sulphate scale during seawater breakthrough. However, the injected chemicals may react physically or chemically react with both the formation and reservoir fluids, thus generating unfavourable wetting alteration and/or formation damage (Jordan et al. 1998; Graham et al. 1999, 2002a; Guan et al. 2003). The risks of formation damage following aqueous scale inhibitor squeeze treatments is a major concern in many reservoirs displaying some degree of water sensitivity (Wat et al, 1999; Collins et al, 1998 & 2000; Mackay et al, 2000). Formation damage normally is manifested by a decline in production following an aqueous-based treatment. Wettability changes and water blocking can worsen the situation dramatically, with formation damage caused by brine and/or chemicals preventing the oil from re-establishing continuity from the pore space to the wellbore. In addition, if new water pathways are established, an increase in postapplication water production may be observed. Moreover, in conventional aqueous squeeze treatments, if the treatment design has not been optimized up to 40% of the injected chemical can be returned during initial well flow back and clean up (Collins 1997a). Non-aqueous scale inhibitor packages are considered to have the capacity to overcome these issues by allowing oil continuity during treatment, while reportedly minimizing relative permeability changes that occur when conventional aqueous fluids are injected into the near-wellbore area (Guan et al. 2004a, 2004b, 2006; Shields et al. 2006, 2008; Graham et al, 2003). Similar to conventional aqueous scale inhibitor squeeze packages, the use of a non-aqueous product is not recognized as equating to a wholly non-damaging treatment (Graham et al. 2002b, 2002c; Jordan et al. 2002). Damage mechanisms, such as in-situ precipitation, mineral damage, fine migration and pore throat blockage, that can arise from the aqueous treatment still exist. Another disadvantage of using hydrocarbon solvents is their heat capacity that tends to be lower than that of water, thereby reducing the near-well cooling effect that benefits inhibitor propagation and perhaps shortening squeeze life. Therefore, it is important to carefully evaluate the non-aqueous packages prior to any field application.

Sand and proppant production pose a safety risk due to erosion, fill of wells and facilities, often resulting in significant deferred production. A number of wells in the Danish offshore sector are currently closed in or beaned back due to proppant production from sand propped fractured wells where proppant is back produced to surface facilities which were not designed with sand handling capability. A new sand consolidation treatment involving enzymatic calcium carbonate scale has been applied to individual zones downhole to remediate failed proppant fractures. The technology is an environmentally friendly alternative to commonly used resins and has the added benefit of being completely reversible. A detailed coiled tubing program was successfully executed in a harsh offshore environment with numerous challenges including identification of sanding zones, chemical contamination, logistics, and selective downhole placement. Laboratory testing was undertaken where unconsolidated proppant was treated with the consolidation chemicals. These results provided important input for defining the placement strategy and indicated that results could be replicated in the field. Successful results have been achieved from this industry first application of enzymatic calcium carbonate scale to consolidate sand propped fractures in a chalk reservoir. The field application supports the laboratory results, where sand free production of over 700 BOPD has been restored in a well previously closed due to proppant production with limited impact on well productivity. A post-job monitoring program has been designed to further evaluate this technology. The development of enzymatic calcium carbonate scale consolidation has led to a method for chemical consolidation of proppant fractures that is more environmentally friendly than alternative methods, is reversible and has limited impact on well productivity. Introduction The Gorm field is a chalk reservoir located in the Danish Offshore sector, created by salt uplift (Nederveen and Damm 1993). It produces from the Danian and Maastrichtian formations via approximately 30 active mainly horizontal production wells. The oil producers are generally completed using the Perforate, Stimulate, Isolate (PSI) concept (Damgaard et al. 1992). Pressure support is provided by four vertical and seven horizontal basal water injectors. The reservoir is tight, with matrix permeability of around 1 mD. The wells are either stimulated by means of matrix acidisation, high rate acid fracturing or sand propped fractures. Proppant and sand are used interchangeably throughout this paper, with both terms referring to the sand based proppant used during stimulation. Three key challenges to production are; scale formation (both barium sulfate and calcium carbonate),pressure maintenance due to irregular waterflood patterns and water short cuts, andsand production from de-stabilised fractures.

Economical field development strategy often implies tie-in of subsea satellite fields to nearby host installations. This leads to a whole new set of benefits and challenges considering design and material selection, production volumes and limitations, company strategies, holistic management and multi-disciplinary approaches. Operation of complex systems with multiple fluid streams demands a broader understanding of the chemical processes taking place when different fluids are mixed. Typical challenges include mineral scale and "soft scale" deposits. To ensure optimum production and provide flow assurance through chemical management, proper monitoring is essential. Guidelines and best practices are even more required if the tie-in to the host includes several operators and service companies. Over the years, the Statoil operated Oseberg asset has through close cooperation with its chemical supplier M-I SWACO systematically improved the sampling and analysis procedures to strengthen the quality of data used in system monitoring. The supplier needs to have a strong focus on flow assurance related to chemical management and provide a range of onshore and offshore monitoring techniques and tools. Challenges from the North Sea Oseberg Field Centre installation with subsea tie-ins have been discussed. Laboratory and field data from bottle tests, chemical analysis, preservation techniques and scaling potential simulations are presented. The results have been used to plan for side stream tests, develop guidelines for early identification of flow assurance challenges, sampling and monitoring of complex fluid systems and chemical management to avoid process upsets and production losses.

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